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Collaborating Authors
Results
Abstract The Mexico South Region produces more than 520, 000 bopdl from mature carbonate reservoirs. These reservoirs have widely varying reservoir pressures, presence of natural fractures and temperatures up to 350 degF. The extremely high temperatures makes even more challenging the stimulation process with conventional systems resulting in excessive corrosion and very inefficient wormholing. An innovative solution, considering a chelating agent as treating fluid, has proved to be an effective approach to stimulate these reservoirs. The post treatment production in two different wells showed outstanding results with higher rates than previous treatments and the trend of the production declination was smoothed. This new stimulation solution aided with a good candidate selection has led it to be the preferred solution for HT wells. Well A was treated with 15.0 m3 of the fluid based on chelating agents as main system, with a solvent preflush and overflush. Previous to this job two stimulation treatments were performed pumping a mixture of conventional acid systems. In both occasions the production increased, however, the production declined to pre-treatment rates in a matter of days. When treated with the new solution the production increased 254 bpd with almost no decrease with time (monitored for three months), indicating a more efficient stimulation treatment, and greatly improved on the economical indicators. Well B was stimulated with 20.0 m3 of chelating agent fluid after three previous attempts using conventional systems. The production increased 726 bpd. Post-treatment behavior was the same as well A. Wells A and B showed an increased production of 1.7 KBD with a very limited production declination because of more efficient wormhole creation due to retarded reaction rates allowing a wide contact with the reservoir thus improving production performance, Np and eliminating post-treatment neutralization and testing surface equipment requirements.
- North America > United States (1.00)
- North America > Mexico (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.34)
- Well Completion > Acidizing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Carbonate reservoirs (1.00)
- Production and Well Operations > Well Intervention (1.00)
Abstract Drilling of the Tyrihans reservoir sections was affected by significant seepage losses. These added up to ~1000 m after drilling five wells with 13 reservoir sections, including pilots and laterals, and a total exposed reservoir length of ~15000 m. In this study, we estimate whether the reported losses can be explained by dynamic filtration mechanisms and related seepage losses. Daily drilling reports were evaluated to reconstruct the downhole drilling environment. Accumulated dynamic and static filter loss periods were calculated. A dynamic filtration HPHT filter press was used to measure dynamic filter losses of laboratory and field samples of the drilling fluid used on Tyrihans. Measurement results were evaluated and extrapolated to field scale. Finally, losses experienced in the field and calculated values were compared. Results strongly indicate that the reported losses on Tyrihans were dynamic seepage losses and that these losses dominate the total loss volumes clearly. The filtration volumes measured in the laboratory were significantly influenced by the shear rate applied. High shear rates caused a larger dynamic filtration component. There are indications that a reduction of coarse bridging particles during drilling and an increase of finer particles relative to the optimum particle size distribution increases the dynamic filtration component. Dynamic fluid losses may in magnitude be misinterpreted as lost circulation into microfractures or in developing fracture systems. A correct assessment of the nature of the losses is essential to select an efficient treatment. Elevated downhole and circulation temperatures as well as long reservoir sections creating large filtration areas cause increased dynamic seepage losses. To reduce these losses higher viscosity base oil could be considered in OBM or a less turbulent flow regime should be engineered. The latter can be achieved for example by increasing drilling fluid viscosity, reducing pump rates or choosing a smaller drill pipe diameter. Efforts should be put into maintaining the optimum particle size distribution of filtercake-building bridging particles. Such changes in fluid design should be carefully evaluated, as they can have a negative impact on other fluid parameters such as equivalent circulation density, swab and surge or reduced hole cleaning efficiency. Research should be initiated to develop low-dynamic-loss fluids. This requires a better understanding of dynamic loss mechanisms and the identification and verification of additives that protect filtercakes against shear and erosion.
- Europe > Norway (0.68)
- North America > United States > Louisiana (0.28)
- Geology > Mineral (0.47)
- Geology > Rock Type > Sedimentary Rock (0.46)
- Europe > Norway > Norwegian Sea > Halten Bank Area > Block 6407/1 > Tyrihans Field > Ile Formation (0.98)
- Europe > Norway > Norwegian Sea > Halten Bank Area > Block 6407/1 > Tyrihans Field > Garn Formation (0.98)
- Europe > Norway > Norwegian Sea > Halten Bank Area > Block 6406/3 > Tyrihans Field > Ile Formation (0.98)
- Europe > Norway > Norwegian Sea > Halten Bank Area > Block 6406/3 > Tyrihans Field > Garn Formation (0.98)
Abstract A good surfactant-based acid should have the following properties: thermal stability, compatibility with cations, low viscosity in live acids but high viscosity in spent acids, ease to be removed by internal or external breakers, and no harm to the environment. Corrosion inhibitors must be added to the acid system to protect well tubulars and minimize the Fe contamination. The components of corrosion inhibitor usually contain short-chain alcohols (e.g. isopropyl alcohol) that can significantly affect the properties of surfactant-based acids. Therefore, corrosion inhibitor plays an important role in evaluating acid systems. Two amine oxide surfactants (S and SW) were examined in this work. The composition of the surfactants was similar, but there was more 1,2 propanediol in surfactant SW. Three corrosion inhibitors (A, B, and C) were tested and all of them contained a certain amount of propargyl alcohol. However, there was a larger amount of isopropanol in corrosion inhibitor A, and more butanol in corrosion inhibitor B. A HPHT rheometer was used to measure the rheological properties (viscosity, G’ and G") of surfactant-based water system, live and spent acids from 75 to 300oF at 300 psi. The results show that the addition of corrosion inhibitor to spent acid significantly reduced its elastic (G’) and viscous modulus (G’’). The maximum temperature that these two surfactants can be used was 220°F. Compared to surfactant-based acids made with corrosion inhibitor B or C, the acids with corrosion inhibitor A showed a much higher viscosity, but phase separation was observed after heating to 300°F. Although corrosion inhibitor B was compatible with surfactants, it adversely influenced the rheological properties of acids. If corrosion inhibitor C was used, the system with surfactant SW can be effectively used at temperatures above 150oF; whereas acids prepared with S1 can be efficiently applied at lower temperatures (<). Cryo-TEM studies showed that corrosion inhibitors affected the rod-like micelle network, which caused the reduced apparent viscosity. Results of this work can be used to better select acid additives to maximize the performance of amine oxide-based acids.
- North America > United States (0.68)
- Asia (0.46)
- Materials > Chemicals > Specialty Chemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.55)
Abstract Well productivity decline have been widely observed for gas wells producing the reservoir fines. The phenomenon has been explained by the lifting, migration and subsequent plugging of the pores by the fine particles, finally resulting in permeability decrease. It has been observed in numerous core flood tests and field cases. The new basic equations for the detachment of fine particles, their migration and size exclusion, causing the rock permeability decline during gas production, have been derived. The analytical model, developed for the regime of steady state gas production with a gradual accumulation of strained particles, exhibits the linear skin factor growth vs the amount of produced reservoir fines. The modeling results are in a good agreement with the well production history. The model predicts well productivity decline due to fines production based on the short term production data.
- North America > United States (1.00)
- Europe (1.00)
- North America > Canada > Alberta (0.28)
- Geology > Mineral > Silicate (0.68)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.46)
Abstract Much has been written about the deepwater Lower Tertiary Wilcox trend in the Gulf of Mexico, which spans hundreds of miles from Alaminos Canyon to Keathley Canyon to Walker Ridge (as well as adjacent areas). The estimated ultimate recoverable oil from these reservoirs is significant: 3 to 15 billion barrels. However, significant technical and reservoir challenges remain because of the water depth (typically greater than 5,000 ft), reservoir depth (typically greater than 20,000 to 30,000 ft below the mud line (BML)), and high pressures (greater than 20,000 psi bottomhole pressure (BHP)). Combining these issues with the thick, low permeability reservoir intervals (more than 1,000 ft thick in the tens of mD) requires new tools as well as new planning and optimization methods. These new planning tools require system-wide (holistic) integration across multiple domains and completion software applications to produce a truly optimized completion. This type of integration is provided by an automated software workflow. Previous papers have provided details about the benefits derived from the automation of operations, engineering, and production workflows in general. Lower Tertiary Wilcox reservoirs were deemed good candidates by a major service company to implement the automated workflow concept, given the reservoirs’ low productivity index (PI), high-cost wells, high pressure/high temperature (HPHT) technical challenges, and production uncertainty. This specific workflow seeks to optimize hydraulic fracture design within Lower Tertiary Wilcox reservoirs by stipulating the maximum net present value (NPV) that satisfies all well, completion, and reservoir constraints. Hydraulic fracture design is an example of what is largely a manual process that requires interaction with several software applications to obtain fracture geometry, production constraints, production sensitivity criteria, and NPV scenarios. When the goal is an optimized fracture design, the process is especially arduous because it requires iterative interactions with reservoir simulators, nodal programs, economics models, well tubular design systems, and stimulation design tools to arrive at a suitable design. Enabling coupled simulations technology, this fracture workflow provides a unique holistic combination of tools, which are linked to reflect the actual economic values.
- Geology > Geological Subdiscipline > Geomechanics (0.93)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.50)
- North America > United States > Texas > East Gulf Coast Tertiary Basin > Wilcox Play > Wilcox Play Formation (0.99)
- North America > United States > Louisiana > East Gulf Coast Tertiary Basin > Wilcox Play > Wilcox Play Formation (0.99)
- North America > United States > Gulf of Mexico > Gulf Coast Basin > Wilcox Trend Formation (0.99)
- (10 more...)
Abstract Building an integrated subsurface model is one of the main goals of major oil and gas operators to guide the field development plans. All field data acquisitions from seismic, well logging, production and geomechanical monitoring to enhanced oil recovery operations can be affected by the accurate details incorporated in the subsurface model. Therefore, building a realistic integrated subsurface model in advance of the field development and associated design and operations is essential for a successful implementation of such projects. Furthermore, utilizing a more reliable model can in-turn provide the basis in the decision making process for control and remediation of formation damage. One of the key identifier of the subsurface model is accurately predicting the hydraulic flow units. There are several models currently used in the prediction of these units based on the type of the data available. The predictions using these models are differing significantly due to the assumptions made in the derivations. Most of these assumptions do not adequately reflect realistic subsurface conditions increasing the need for better models to enhance the predictions. A new approach has been developed in this study for predicting the petrophysical properties improving the reservoir characterization. Poiseuille flow equation and Darcy equation were coupled taking into consideration the irreducible water saturation in the pore network. The porous media was introduced as a domain containing bundle of tortuous capillary tubes with irreducible water lining the pore wall. A series of routine and special core analysis were performed on 17 Berea sandstone samples and the petrophysical properties were measured and XRD analysis was conducted. In addition, core permeabilities were predicted using a new permeability model and the results were compared to the measured permeability data. In building the petrophysical model, it was initially necessary to assume an ideal reservoir with 17 different layers. Afterwards, by iteration and calibration of the laboratory data, the more realistic number of hydraulic flow units was determined accordingly. The same model was also implemented to a Cotton Valley tight gas reservoir in Northern Louisiana in order to determine the flow units. A comparative study shows that the new model provides a better distribution of hydraulic flow unitsand prediction of the petrophysical properties. Using the new model provides a better match with the experimental data collected than the models currently used in the prediction of such parameters. The good agreement observed for both the Berea sandstone and Cotton Valley tight gas sand experimental data and the model predictions using the new permeability model show the wider range of applicability for various reservoir conditions.
- North America > United States > Ohio (0.69)
- North America > United States > Texas (0.68)
- North America > United States > Louisiana (0.67)
- (3 more...)
- North America > United States > Mississippi > Pond Field (0.99)
- North America > Mexico > Veracruz > Tampico-Misantla Basin > San Andres Field (0.99)
- Asia > Middle East > Kuwait > Ahmadi Governorate > Arabian Basin > Widyan Basin > Greater Burgan Field > Wara Formation (0.99)
- (9 more...)
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
Abstract The core permeability decline during corefloods with varying water composition, especially with low salinity water, has been widely reported in the literature. It has often been explained by the lifting, migration and subsequent plugging of pore throats by fine particles, which has been observed in numerous coreflood tests with altered water composition. In this work, the concept of using this permeability decline in order to decrease water production during pressuredepletion in gas field is investigated. The small volume injection of fresh water into an abandoned watered-up well in order to slow down the encroaching aquifer water is discussed. Equations for two-phase immiscible compressible flow with fines migration and capture have been derived. In large scale approximation, the equations are transformed to the black-oil polymer flooding model. The performed reservoir simulation shows that injection of fresh water bank significantly decreases water production and improves gas recovery.
- Europe (1.00)
- North America > United States > Louisiana (0.28)
- North America > Canada > Alberta (0.28)
- Geology > Geological Subdiscipline (0.66)
- Geology > Mineral > Silicate (0.46)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.46)
Abstract Water shutoff using polymer gels has been practiced with success for long time. However, in certain cases, there is a need to acidize a well while isolating part of it using a gel treatment especially in long horizontal wells. The application of combined treatment is challenging and has resulted in a mixed outcome. The acid reacts with carbonate around the gel destroying the benefits of the gel treatment. Likewise, the application of the gel post an acidizing treatment is ineffective. The objective of this paper is to investigate the effectiveness of combining water shut-off and acidizing in one treatment in carbonate formations. Core-flood testing was conducted to investigate the effectiveness of water shut-off gels before and after acidizing the core plug. Two scenarios were examined; the first one included pumping a cross-linked organic polymer gel to a carbonate core plug then followed by emulsified acid. In the second scenario, the core plug was acidized then the gel treatment was pumped. The gelling system consisted of polymer and dual set of delayed organic crosslinkers. The acid was 20 wt% emulsified HCl. CT scanning images were obtained before and after each step. The testing was performed at 200°F and 500 psi pore pressure. The core flood experiments showed that when acid was applied after the gel treatment wormholes were created and dissolved the rock around the gel. On other hand, when the gel was applied after the acid, the gel was not able to withstand the differential pressures and allowed the flow of water because of the inability of the gel to plug the wormholes. It was demonstrated that the gel and acid treatments must be isolated from each other by mechanical means or deeper penetration of the gel.
Abstract Reservoir drilling and completion fluids are affected by temperature. Fluids that perform well at one temperature range can experience major problems at higher temperature ranges. A series of studies have been conducted over the last four years looking in detail at the effect of reservoir drilling fluid design for high-temperature, high-pressure (HTHP) reservoirs, with significant developments in the understanding of the role of fluid loss additives. The focus of these studies was to reduce and control formation damage, in addition to allowing efficient drilling and effective logging of exploration wells. This paper reviews and explains the findings of these investigations and the significance on past and future reservoir exploration and drilling operations. The studies were all required to assist in a number of specific drilling campaigns where logging of reservoir pressures was planned or had been performed and was believed to be influenced by formation damage. The investigations were initiated with sufficient time to allow hundreds of formulations to be tested with regards to drilling properties, stability and formation damage. Very distinctive improvements in HTHP return permeability and filter cake thickness were obtained, which was accompanied by logging success. The most notable controlling factor of return permeability under HTHP conditions was determined to be the fluid loss additive. The selection and quantity of fluid loss additive was so significant that it alone could vary the return permeability by more than 80%. The findings from these investigations have been put to practical use in a number of exploration wells where pressure measurements have been taken with great success. One notable investigation focused on a formulation used 10 years ago on a reservoir where pressure measurements could not be taken. The reservoir was abandoned until recently due to the apparent lack of pressure. This paper details the problems encountered and the results of the investigation in addition to the techniques used to prevent similar problems occurring again.
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (1.00)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid management & disposal (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > HP/HT reservoirs (1.00)
Abstract Fluid loss control is an essential property of oil based mud (OBM) which can impact the success of drilling operations. The paper presents an investigation of the mitigation of lost circulation in OBM using leak-off control additive. A simple physical model was developed to describe the static filtration process considering the formation and properties of the filter cake. Both HTHP API press and core flow filtration experiments were performed to evaluate the leak-off behavior of OBM. Core filtration experiments were carried with the aid of a CT scanner to monitor the invasion of the filtrate into the sandstone core at time intervals. In the long time limit the model predicts that the fluid loss follows the classical Carter equation, i.e. the leak of volume increases as the square root of time for the static filtration through a filter paper and through the sandstone core. Dual mode filtration diminishes the rate of fluid loss. The model provides also a relation between pressure drop and filtrate rate, which can be used to estimate the permeability of filter cake in the experiment. The leak-off behavior with additive observed in the experiment is well explained by the microstructure of rapid built-up filter cake which is mainly responsible for the control of fluid loss. The role of different components of OBM, e.g. solid particles, emulsion droplets and additives is discussed in the light of our observations.
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.46)
- Geology > Mineral (0.31)